Drilling wells for oil and gas production conventionally employ longitudinally extending sections, or so-called “strings,” of drill pipe to which, at one end, is secured a drill bit of a larger diameter. The drill bit conventionally forms a bore hole through the subterranean earth formation to a selected depth. Generally, after a selected portion of the bore hole has been drilled, the drill bit is removed from the bore hole so that a string of tubular members of lesser diameter than the bore hole, known as casing, can be placed in the bore hole and secured therein with cement. Therefore, drilling and casing according to the conventional process typically requires sequentially drilling the bore hole using drill string with the drill bit attached thereto, removing the drill string and drill bit from the bore hole, and disposing and cementing a casing into the bore hole.
Rotary drill bits are commonly used for drilling such bore holes or wells. One type of rotary drill bit is the fixed-cutter bit (often referred to as a “drag” bit), which typically includes a plurality of cutting elements secured to a face region of a bit body. Referring to FIG. 1, a conventional fixed-cutter rotary drill bit 100 includes a bit body 110 having a face 120 defining a proximal end and comprising generally radially extending blades 130, forming fluid courses 140 therebetween extending to junk slots 150 between circumferentially adjacent blades 130. Bit body 110 may comprise a composite matrix or a steel body, both as known in the art.
The drill bit includes an outer diameter 155 defining the radius of the wall surface of a bore hole. The outer diameter 155 may be defined by a plurality of gage regions 160, which may also be characterized as “gage pads” in the art. Gage regions 160 comprise longitudinally upward (as the drill bit 100 is oriented during use) extensions of blades 130. The gage regions 160 may have wear-resistant inserts and/or coatings, such as hardfacing material, tungsten carbide inserts natural or synthetic diamonds, or a combination thereof, on radially outer surfaces 165 thereof as known in the art to inhibit excessive wear thereto so that the design borehole diameter to be drilled by the drill bit is maintained over time.
A plurality of cutting elements 180 is conventionally positioned on each of the blades 130. Generally, the cutting elements 180 have either a disk shape or, in some instances, a more elongated, substantially cylindrical shape. The cutting elements 180 commonly comprise a “table” of super-abrasive material, such as mutually bound particles of polycrystalline diamond, formed on a supporting substrate of a hard material, conventionally cemented tungsten carbide. Such cutting elements are often referred to as “polycrystalline diamond compact” (PDC) cutting elements or cutters. The plurality of PDC cutting elements 180 may be provided within cutting element pockets 190 formed in rotationally leading surfaces of each of the blades 130. Conventionally, a bonding material such as an adhesive or, more typically, a braze alloy may be used to secure the cutting elements 180 to the bit body 110.
The bit body 110 of a rotary drill bit 100 typically is secured to a steel shank 200 having an American Petroleum Institute (API) threaded connection for attaching the drill bit 100 to a drill string (not shown). Top transition surfaces 210 are located at the upper ends of the gage regions 160 between the outer diameter defined by the radially outer surfaces 165 of gage regions 160 and a shank shoulder 220. Transition edges 230 are defined between the radially outer surfaces 165 of gage regions 160 and their respective, associated top transition surfaces 210.
During drilling operations, the drill bit 100 is positioned at the bottom of a well bore hole and rotated. Drilling fluid is pumped through the inside of the bit body 110, and out through nozzles (not shown). As the drill bit 100 is rotated, the PDC cutting elements 180 scrape across and shear away the underlying earth formation material. The formation cuttings mix with the drilling fluid and pass through the fluid courses 140 and then through the junk slots 150, up through an annular space between the wall of the bore hole and the outer surface of the drill string to the surface of the earth formation.
When drilling in unconsolidated, highly abrasive and/or hardened formations as well as in other formation materials, the radially outer surface of the gage regions 160 of the drill bits are subjected to wear caused by the abrasive cuttings being drilled, the high sand content in the mud, and the sand particles along the borehole wall. Improvements in the wear-resistant inserts and/or coatings have helped to limit the accelerated wear from occurring to the radially outer surfaces 165 of the gage regions 160 in the normal (i.e., downward) drilling mode. However, when the drill bit 100 is reversed in the bore hole, such as when back reaming or up drilling is performed, substantial wear to the top transition surfaces 210 including the transition edges 230 located near the shank 200 end of the bit may occur. Such wear causes rounding over the gage region 160 and eventually will significantly wear the gage region 160.